GREENHOUSE GASES FROM

GEOTHERMAL POWER PRODUCTION

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E S M A P M I S S I O N

The Energy Sector Management Assistance Program (ESMAP) is a global

knowledge and technical assistance program administered by the World

Bank. It provides analytical and advisory services to low- and middle-

income countries to increase their know-how and institutional capac-

ity to achieve environmentally sustainable energy solutions for poverty

reduction and economic growth. ESMAP is funded by Australia, Austria,

Denmark, Finland, France, Germany, Iceland, Lithuania, the Netherlands,

Norway, Sweden, and the United Kingdom, as well as the World Bank.

Copyright © April 2016

The International Bank for Reconstruction

And Development / THE WORLD BANK GROUP

1818 H Street, NW | Washington DC 20433 | USA

Energy Sector Management Assistance Program (ESMAP) reports are published to communicate the results of ESMAP’s work to the develop-

ment community. Some sources cited in this report may be informal documents not readily available.

The findings, interpretations, and conclusions expressed in this report are entirely those of the author(s) and should not be attributed in any

manner to the World Bank, or its affiliated organizations, or to members of its board of executive directors for the countries they represent,

or to ESMAP. The World Bank and ESMAP do not guarantee the accuracy of the data included in this publication and accept no responsibil-

ity whatsoever for any consequence of their use. The boundaries, colors, denominations, and other information shown on any map in this

volume do not imply on the part of the World Bank Group any judgment on the legal status of any territory or the endorsement of acceptance

of such boundaries.

The text of this publication may be reproduced in whole or in part and in any form for educational or nonprofit uses, without special permis-

sion provided acknowledgement of the source is made. Requests for permission to reproduce portions for resale or commercial purposes

should be sent to the ESMAP Manager at the address below. ESMAP encourages dissemination of its work and normally gives permission

promptly. The ESMAP Manager would appreciate receiving a copy of the publication that uses this publication for its source sent in care of

the address above.

All images remain the sole property of their source and may not be used for any purpose without written permission from the source.

Written by | Thráinn Fridriksson, Almudena Mateos, Pierre Audinet, and Yasemin Orucu

Energy Sector Management Assistance Program | The World Bank

ii

T A B L E O F C O N T E N T S

Acronyms and Abbreviations ii

Acknowledgements iii

Key Findings 1

1 | GEOTHERMAL SYSTEMS AND UTILIZATION 5

2 | GASES AND THE GEOTHERMAL CYCLE 7

2.1. Gases in Geothermal Fluids 7

2.2. Natural Sources and Sinks of CO2 in Geothermal Systems 8

2.3. Effects of Power Production on the CO2 Budget of Geothermal Systems 11

3 | GHG EMISSIONS FROM GEOTHERMAL POWER PLANTS 17

3.1. Assessments of Plant Cycle GHG Emissions from Geothermal Projects 17

3.2. Global and National Surveys on Operational GHG Emissions 18

3.3. High Emission Outliers 19

4 | TECHNICAL OPTIONS TO MITIGATE CO2 EMISSIONS FROM GEOTHERMAL POWER PLANTS 21

4.1. Energy Conversion Technologies and CO2 Emissions 21

4.2. Gas Sequestration Technologies 25

5 | ASSESSING GHG EMISSIONS FROM GEOTHERMAL POWER PROJECTS 29

5.1. Estimating Emission Factors from Greenfield Projects 31

5.2. Estimating Emission Factors for Brownfield Projects 34

5.3. Constraining Emission Factors for Existing Projects 35

5.4. Estimating Plant Cycle Emission Factors for Geothermal Power Projects 35

6 | ADDRESSING KNOWLEDGE GAPS THROUGH INVESTMENT PROJECTS 37

6.1. Long-term Changes in GHG Emissions from Power Plants 37

6.2. Effects of Production on GHG Emissions through Soil and Fumaroles 38

6.3. Cost of GHG Capture and Treatment 38

REFERENCES 41

List of Figures and Tables

Figure 1 Approach to Define GHG Emission Factors from Greenfield Geothermal Projects 3

Figure 2.1 Natural Sources and Sinks of CO2 in a Volcanic Geothermal System 11

Figure 2.2 Volcanic Geothermal System Processes Affecting CO2 Emissions 12

Figure 2.3 CO2 Emissions from the Reykjanes Geothermal System, Iceland 15

Figure 5.1 Emission Factors of Geothermal Power Compared to Fossil Fuel 30

Figure 5.2 Approach to Define GHG Emission Factors from Greenfield Geothermal Projects 32

Table 2.1 Typical Composition of Geothermal Gas 7

Table 4.1 Resource Temperature Ranges Suitable for the Different Energy Conversion Technologies 25

ii

A C R O N Y M S A N D A B B R E V I A T I O N S

ARPAT Regional Environmental Protection Agency for Tuscany

Bar-a Bar absolute (absolute pressure)

Bar-g Bar gauge (absolute pressure minus atmospheric pressure)

CDM Clean Development Mechanism

EFGHG

Greenhouse Gas Emission Factor

EOR Enhanced Oil Recovery

g/kWh Gram per kilowatt hour

gCO2/kWh Gram CO

2 per kilowatt hour

gCO2e/kWh Gram CO

2 equivalent per kilowatt hour

GHG Greenhouse gas

LCA Life Cycle Analysis

LRSR Liquid Redox Sulfur Recovery

MW Megawatt (in this report, MW refers to electric power)

MWe Megawatt electric power

MWt Megawatt thermal

NCG Non-condensable gas

ppm Parts per million

ppm-V Parts per million on volume basis

t /day Metric tonne per day

US DOE United States Department of Energy

USD/t United States dollar per metric tonne

All currency in United States dollars (USD or US$), unless otherwise indicated.

iii

A C K N O W L E D G M E N T S

This Interim Technical Note was prepared by Thráinn Fridriksson (Energy Specialist), Almudena

Mateos (Energy Specialist), and Pierre Audinet (Senior Energy Economist) at the Energy Sector

Management Assistance Program (ESMAP) of the World Bank. The note benefited from a thorough

review process which refined its focus and content and drew upon wide ranging experience and

expertise of World Bank specialists and a panel of external reviewers representing geothermal

developers, technical practitioners, researchers, and other multilateral financial institutions. The

internal peer reviewers were Peter Johansen (Senior Energy Specialist, GEE02), Karan Kapoor (Senior

Energy Specialist, GEESO), and Rikard Liden (Senior Hydropower Specialist, GWAGS). The external

review panel included: Ruggero Bertani (Director of Innovation and Sustainability, Enel Green Power,

Italy), Yoram Bronicki (Former Director and Chairman of the Board of Directors of Ormat Technologies,

USA), Annika Eberle (Engineering Researcher, National Renewable Energy Laboratory, USA), Karl

Gawell (Executive Director, Geothermal Energy Associates, USA), Magnus Gehringer (CEO, Consent

Energy, USA), Bill Harvey (Project Engineer, Power Engineers, USA), Garvin Heath (Senior Scientist,

National Renewable Energy Laboratory, USA), Adonai Herrera (Senior Manager, Energy Efficiency

and Climate Change, EBRD, Turkey), Mike Long (Senior Project Manager, Power Engineers, USA),

Benjamin Matek (Industry Analyst and Research Project Manager, Geothermal Energy Associates,

USA), Ed Mrozcek (Senior Scientist, GNS Science, New Zealand), Ann Robertson-Tait (Business

Development Manager/Senior Geologist, GeothermEx, USA), Anna Wall (Energy Technologies Analyst,

National Renewable Energy Laboratory, USA). Barbara Ungari and Maria Elisa Passeri (Consultants,

GEEES) are acknowledged for their help with data collection and analysis.

1G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

K E Y F I N D I N G S

Geothermal is a renewable source energy that can be used directly for heating or for power production.

Geothermal utilization, particularly power production, may result in some greenhouse gas (GHG)

emissions. GHG emissions from geothermal power production is generally small in comparison to

traditional base load thermal energy power generation facilities. This is mainly due to the fact that

the large majority of installations draw their geothermal energy from geothermal reservoirs with low

GHG concentrations. However, as the geothermal sector has expanded, a wider range of geothermal

resources have been brought into exploitation, including geothermal systems with relatively high GHG

concentrations in the reservoir fluid. There is a growing realization within the geothermal community that

geothermal power plants can, in rare instances, release significant quantities GHG into the atmosphere.

This interim technical note presents an overview of the current knowledge on GHG emissions from

geothermal systems and geothermal power plants, and gives guidance on how to assess GHG

emissions from geothermal projects when this is required, depending on their stage of development.

This note identifies critical knowledge gaps and presents recommendations as to how close these

gaps and proposes an interim methodology to estimate GHG emissions from geothermal projects that

financing institutions, such as the World Bank, intend to support. The plan is to update this note when

the proposed methodology has been tested by application to actual projects and some of the current

knowledge gaps have been closed as more information become available.

As a result of the relatively low GHG emission factors from geothermal power production, this issue

has so far received limited attention in the scientific community. However, awareness is increasing as

efforts are undertaken to curb GHG emissions globally. There are still a number of uncertainties that

surround the understanding of GHG emissions from geothermal power production. One such example

of uncertainty is with regards to trends in emissions over a plant’s lifetime. Volumes, pressure, and

composition of gases present in geothermal fluids that remain uncondensed after energy extraction

fluids are monitored as part of normal geothermal plant operations. During the operation of geothermal

power plants, there is a gradual decline in non-condensable gas (NCG) concentration in the reservoir

fluid and, thus, gradually decreasing gas emissions can happen. This is largely a result of reinjection of

gas free of geothermal brine into the peripheries of the reservoir. However, gradual gas decrease has

not been systematically documented (in part because power plants do not have to publicly report such

data). Another uncertainty is related to how the production of electricity from geothermal reservoirs

may affect natural GHG emissions through the Earth’s surface. GHG is continuously emitted naturally

from geothermal reservoirs (i.e., without any drilling or power production taking place), diffusing

through the soil and steam vents.

The national regulatory frameworks for carbon emissions from geothermal power production varies

from country to country, reflecting the limited understanding of the effects of power production on

natural surface emissions, the minuscule size of the geothermal sector compared to other segments of

2K e y F i n d i n g s

the electricity generation sector, and its proportionately small (potential) GHG emissions contribution.

In some countries, GHG emissions from geothermal power are not considered anthropogenic, in

accord with the understanding that emissions from power plants are counterbalanced by reduction

in surface emissions as described above. In other countries, geothermal power producers that emit

more than a given volume of GHG per annum are now required by policies to monitor and report

their emissions.

GHGs are naturally present in all geothermal fluids, and thus geothermal power production from

intermediate to high temperature geothermal resources generally leads to some GHG release into the

atmosphere. The dominant NCG in geothermal fluids is carbon dioxide (CO2), typically constituting

more than 95 percent of the total NCG content. The other relevant GHG in geothermal fluids is methane

(CH4), whose concentration is generally a few hundredths to a few tenths of a percent by mass, but

can in rare cases make up more than 1.5 percent of the total gas (i.e., amounting to more than 30

percent of the GHG emissions as CH4 traps thermal radiation more efficiently than CO

2). However, the

vast majority of available data on GHG emissions from geothermal power plants refers to CO2 only. As

a result, the discussion in this note on GHG emissions from geothermal power production is mainly

focused on CO2 emissions.

In 2001, the global average estimate for operational GHG emissions from geothermal power

production was 122 gCO2/kWh, based on a survey involving emissions from power plants that

constitute more than 50 percent of the geothermal capacity installed worldwide. Available data

from the United States and New Zealand are consistent with these global emission values, resulting

in average figures of 106 g CO2/kWh (in 2002) and 123 g CO

2e/kWh (in 2012), respectively. The

country-wide weighted average emission estimate for Iceland is lower 34 g/kWh (in 2013), and the

corresponding value for Italy is higher at 330 g CO2/kWh (in 2013).

In a few exceptional cases, the emission from geothermal power plants can be significantly higher

than the averages above, even above the values of thermal fossil-fueled power plants (which can

reach 1,030 g CO2/kWh for a subcritical circulating fluidized bed coal-fueled power plant and 580 g

CO2/kWh for an open cycle gas-fueled power plant). The most extreme reported GHG emission values,

900 to 1,300 g CO2/kWh are from power plants located in the Menderes and Gediz grabens in South

West Turkey. Fairly high values have also been reported in some power plants from Mount Amiata,

Italy, and Ngawha, New Zealand. Such high GHG emissions seem to be restricted to high temperature

geothermal reservoirs located in carbonate rich rocks, which are a rare occurrence.

This note proposes a way to estimate future emission factors for geothermal projects under

development. For instance, if a pumped binary power plant is planned, the emission factor will be

0. Projects using other energy conversion technologies will result in some emissions. For projects

where wells have been drilled and tested, formulas are provided to compute emission factors based

on the chemical composition of the geothermal fluid and the design parameters of the power plant.

For projects located in the vicinity of existing power plants in analogous geologic settings, emission

factors from the existing plants can be used.

3G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

Where no such analogs are available, emission factors can be roughly estimated based on the

expected geology of the geothermal reservoirs. For instance, for power projects located where

carbonate rocks are expected at reservoir level, emission factors can be estimated at 790 g

CO2e/kWh. If volcanic rocks are expected or where no such information is available, future emissions

are estimated to be equal to the global average or 128 g CO2e/kWh. This approach is summarized

by Figure 1.

If Plant Cycle emissions are to be included, it is recommended that a Plant Cycle GHG emission factor

of 10 g/kWh is used for a project lifetime of 30 years.

The entity financing or implementing financing to develop a given geothermal electricity production

project is best suited to gather data that could help close some of the existing knowledge gaps

related to GHG emissions from geothermal power production. First, GHG emission data should be

systematically collected from geothermal power projects in order to monitor the changes in GHG

F I G U R E 1

Approach to Define GHG Emission Factors from Greenfield Geothermal Projects

Exis�ng geothermal power plants in analogous geological se�ng

Explora�on wells drilled and discharge tested; pumped binary not feasible

Carbonate rocks expected at reservoir level

unless

Compute an an�cipated emission factor from (i) the average GHG concentra�on in steam or total fluid, weighted by well produc�vity and (ii) the an�cipated steam or fluid consump�on factor for the selected energy conversion technology (see Box 5.2)

Use GHG emission factors from neighboring / analogous power plants, if available and if geological condi�ons are comparable

An�cipate high GHG emission factors – 790 gCO2e/kWh

As a default, assume GHG emission factors are equal to the global weighted average CO2 emission factor, 128 gCO2e/kWh

Available Informa�on Es�ma�on of GHG Emission Factor

Pumped binary technology an�cipated Assume emission factor of 0 gCO2e/kWh

No informa�on on geology or energy conversion technology OR volcanic rocks

expected at reservoir level

or

or

or

4K e y F i n d i n g s

emission factors over time. Second, it is also recommended that, when possible, funding should

be provided for baseline studies of surface GHG emissions in geothermal areas before geothermal

power production commences, followed by periodic surveys once production has started. This will

provide much needed data on the effects of geothermal power production on gas emissions through

the surface. Finally, project sponsors are encouraged to conduct a feasibility study of GHG capture

and treatment options, in particular for geothermal power projects that are likely to result in GHG

emissions in excess of the grid emission factor in a given country. This will encourage the use of

GHG capture technologies, where economically feasible, and provide more detailed information

about the cost of these technologies.

Divided into two parts, this report complements the World Bank Guidance Manual for Greenhouse Gas

Accounting for Energy Investment Operations (World Bank, 2015) by presenting methods to predict

and estimate GHG emission factors for geothermal projects at different stages of development.

Part I is a review of the existing knowledge on GHG emissions from geothermal systems and power

plants, focusing on the following questions:

• What is the average and range of GHG emissions from geothermal power plants worldwide?

• What are the geological factors that affect GHG emissions from geothermal power plants?

• Do GHG emissions from geothermal power plants change over time?

• Does geothermal power production affect the amount of GHG released through natural pathways

from the geothermal system?

• Does the energy conversion technology affect GHG emissions?

• What are the options for GHG capture from geothermal power plants?

Part II provides guidance on methods to quantify GHG emissions from geothermal power projects.

5

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G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

G E O T H E R M A L S Y S T E M S A N D U T I L I Z A T I O N

A geothermal system can be defined as a thermal anomaly in the Earth’s upper crust where convecting

fluid transfers heat from a heat source at depth towards the surface. Geothermal systems range in

reservoir temperature from near ambient conditions to over 350°C. Geothermal systems are commonly

classified based on the reservoir temperature into low (<100–150°C), intermediate (between 100–

150°C and 200°C) and high temperature (>200°C) geothermal systems.1

The division into low, intermediate, and high temperature geothermal systems reflects the different

uses of geothermal depending on the resource temperature. Low temperature systems are suitable

for direct applications, such as space heating, drying, spa applications, etc. Intermediate and

high temperature systems are suitable for power production, using different energy conversion

technologies. Power production from intermediate temperature geothermal systems can be

accomplished using binary technology, whereas conventional condensing turbines are most

commonly used for power production from high temperature systems (ESMAP, 2012).

High temperature geothermal systems can also be classified based on the dominant state of the

fluid in the reservoir (i.e., as liquid-dominated or vapor-dominated systems). Purely vapor-dominated

(dry steam) systems are less common than liquid dominated systems but steam dominated zones

or “steam caps” within liquid-dominated reservoirs in production are not uncommon (see Box 2.1

and Section 2.3.1). This has implications for the presence of geothermal gases as they partition

preferentially into the vapor phase. Higher gas emissions can be expected from geothermal power

plants producing from vapor-dominated systems or steam zones as opposed to fully liquid-dominated

reservoirs. Low and intermediate temperature geothermal systems are always liquid dominated.

Geothermal systems can also be classified by their geological nature. Volcanic geothermal systems

are the most common high temperature geothermal systems. These systems are characterized by

a volcanic heat source, such as hot intrusions or magma. Volcanic geothermal systems are found

in volcanically active areas along tectonic plate boundaries and also in association with intraplate

volcanism in some cases. Not all volcanic systems develop geothermal systems. Low temperature

systems are commonly convective fracture controlled systems where water circulates in deep

fractures, mining the heat from the rocks at depth. These fracture controlled systems generally do not

have a magmatic heat source but can still have intermediate to high temperatures when located in

areas of high heat flow. The geothermal systems in the Basin and Range2 area of the Southwest United

States and the Aegean region of Turkey are examples of hot fracture controlled systems in areas of

high heat flow due to extensional tectonics and resulting crustal thinning.

Utilization of low temperature geothermal systems does not generally result in significant gas emissions.

This is due to the fact that the gas content in geothermal fluids is to some degree correlated with

reservoir temperature, so low temperature fluids are generally gas poor. Furthermore, utilization of low

temperature fluids quickly becomes uneconomical when gas content is significant (see Section 6.1).

PA

RT

I

GH

GS

A

ND

G

EO

TH

ER

MA

L E

NE

RG

Y

6C h a p t e r 1

As a result, this note focuses on gas emissions from medium and high temperature geothermal

resources used for power production.

ENDNOTES

1More information on the different classifications schemes for geothermal systems can be found at the IGA website

(http://www.geothermal-energy.org/what_is_geothermal_energy.html)

2The term Basin and Range refers to a geographic area in the Southwest United States and Northwest Mexico that

is characterized by crustal extension, which has resulted in the formation of long narrow mountain ridges separated

by flat valleys.

7

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G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

G A S E S A N D T H E G E O T H E R M A L C Y C L E

2.1. GASES IN GEOTHERMAL FLUIDS

Gases are naturally present in geothermal fluids. Geothermal gases are dissolved in the liquid phase at

the reservoir level, but where steam is present the gases partition preferentially into the steam phase.

Common geothermal gases are CO2, H

2S, H

2, N

2, CH

4, NH

3, and Ar, but other gases are also present

in trace amounts. A common compositional range of geothermal gases is shown in Table 2.1.

Table 2.1 illustrates how CO2 is generally the dominant geothermal gas, typically constituting more than

95 percent of the total gas. Other significant gases are H2S and N

2, the weight of which, in rare cases,

can constitute several percentage points of the total geothermal gas. Other gases are generally found

in low concentrations in the order of a few percent to a fraction of a percent.

CO2 and CH

4 are the only relevant GHG species in geothermal fluids. While CO

2 is the most abundant

GHG, CH4 is generally present in small concentrations as well. However, due to its relatively strong

global warming potential,3 CH4 may have a significant contribution to the overall GHG emissions from

geothermal power plants. Unfortunately, data on CH4 emissions from geothermal power plants are

not available for all systems for which there are CO2 emission data. As a result, it is difficult to assess

the CH4 contribution to GHG emissions from geothermal power production to the same extent as is

possible for CO2. Available data suggest that CH

4 emission, in terms of CO

2 equivalents, ranges from

a fraction of a percent to more than one-fourth of the total GHG emissions in the most extreme cases.4

As a result, it can be assumed that the magnitude of the global warming effect of CH4 emissions from

geothermal power plants is generally smaller than that of CO2, but CH

4 emissions may represent a

significant fraction of the total GHG emissions in some cases. However, since data on CH4 emissions

from geothermal power plants is limited, the discussion below will focus on CO2.

In the context of geothermal power production, the geothermal gases are commonly referred to as

non-condensable gases (NCGs) as they do not condense at the same physical conditions as water

vapor but remain in the gas phase. NCGs have a negative effect on the efficiency of the energy

conversion process and need to be removed from the system (either from the condenser or the heat

T A B L E 2 . 1

Typical Composition of Geothermal Gas (weight % dry gas)

CO2

H2S H

2CH

4NH

3N

2AR

Median 95.4 3.0 0.012 0.15 0.29 0.84 0.02

Maximum 99.8 21.2 2.2 1.7 1.8 3.0 0.04

Minimum 75.7 0.1 0.001 0.0045 0.005 0.17 0.004

Note | Based on 15 representative steam analyses from high temperature systems in Europe, North-America, Central-America, Africa,

Asia and Oceania (from Arnórsson et al., 2007).

8C h a p t e r 2

exchangers, see section 6.1). Gas removal systems add to the capital costs of geothermal power

plants and can, in some cases, also consume a considerable amount of the plant’s power production.

These systems are designed to cope with a specific range of NCG content in the steam or the total

fluid. Accurate estimation of the NCG content in the geothermal fluid, thus, is one of the most critical

design parameters for geothermal power plants.

2.2 NATURAL SOURCES AND SINKS OF CO2 IN GEOTHERMAL SYSTEMS

Different geothermal gases have different origins and CO2 in particular can derive from three main

sources:

1 | A small fraction of the CO2 in a geothermal reservoir may have the same origin as the

geothermal fluid itself. This is the CO2 that is dissolved in the recharging fluid, sea water, or

meteoric water when it enters the geothermal system. This is generally an insignificant fraction

of the total CO2 dissolved in geothermal fluids.

2 | A large fraction of the CO2 in geothermal fluids may be derived from the host rock of the

geothermal system. Igneous rocks, which are the dominant rock type in volcanic geothermal

systems, contain a small amount of carbonate that is released due to chemical interactions

between the rocks and the fluids. Therefore, the concentrations of CO2 in volcanic geothermal

systems can be moderate if rock dissolution is the major source of CO2 in the fluid. This

applies, for instance, to the Reykjanes, Hellisheidi, and Nesjavellir systems in Iceland

(see Box 2.1). Other rock types may release larger quantities of CO2 into the geothermal fluids,

such as carbonate rocks, which have carbonate as a major constituent. Such rocks

may release large amounts of CO2 to the geothermal fluids upon dissolution or through

metamorphic processes at high temperatures (see Box 2.2). Carbonate-hosted high temperature

geothermal systems are not common but they do occur (notably in the Tuscany region of Italy and

western Turkey) and are characterized by significantly higher CO2 fluid concentrations than other

geothermal reservoirs. Other types of sedimentary rocks contain variable amounts of carbonate,

resulting in a range of CO2 concentrations in the geothermal fluids.

3 | CO2 may enter the geothermal reservoir from below, either from deep crustal or mantle sources

or from magma bodies, which are the heat sources of many volcanic geothermal systems.

Magmatic CO2 can enter geothermal reservoirs in pulses related to magmatic intrusions

such as in Krafla, Iceland (see Box 2.1), or more continuously such as in Mt. Amiata, Italy, or

Ohaaki, New Zealand (Haizlip et al., 2013).

The sinks of geothermal CO2 include precipitation of carbonate minerals in or above the geothermal

reservoir, emission to the atmosphere through steam vents or diffusely through the soil, and dissolution

in ground waters after ascent from the geothermal reservoir. Geothermal steam emitted from steam

vents may, in some cases, be a good indicator of the composition of the gas in the reservoir. However,

secondary processes, such as steam condensation, boiling of shallow ground waters, and chemical

reactions between gases in the steam and the bed rock and soil, may significantly alter the steam

9G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

B O X 2 . 1

CO2 Emissions from Icelandic Power Plants, 1977 to Present

Total CO2 emissions from Icelandic power plants and emissions from individual plants shown in the figure

below. This figure highlights two important points. First, it shows that emissions from individual systems in

Iceland span a wide range. Second, it illustrates that emissions from individual systems have changed significantly

over time. Emissions from the most recent power plants, Nesjavellir, Hellisheidi, and Reykjanes, have historically

been under 60 g/kWh and in the recent years have fallen to a range from 15 to 30 g/kWh. Annual average

emissions from the other three power plants have been between 100 and 470 g/kWh throughout much of their

history but in recent years have been lower, or around 50 g/kWh for Krafla and Bjarnarflag and around 100 g/kWh

in Svartsengi.

All the Icelandic geothermal power plants are producing from basalt-hosted geothermal systems (Arnórsson,

1995) so the variation in gas emissions cannot be attributed to different rock compositions. Similarly, the levels

CO2 Emission from Geothermal Power Plants in Iceland, 1977–2013

Source | Data from Baldvinsson et al., 2009 and personal communications with Landsvirkjun, Reykjavik Energy, and HS Orka.

0

100

200

300

400

500

600

1975 1980 1985 1990 1995 2000 2005 2010 2015

CO2

Emis

sion

s (g

/kW

h)

Reykjanes

Svartsengi

Hellisheidi

Nesjavellir

Bjarnarflag

Krafla

Total

10C h a p t e r 2

of gas emissions cannot be attributed to the origin of the fluid; the geothermal fluid in Reykjanes is of seawater

origin, while in Svartsengi, the fluid is two-thirds seawater and one-third meteoric water. The fluid in the other four

systems is of meteoric origin. The different character of the gas emissions in these six systems can be attributed

to different processes that have taken place in these systems—degassing of shallow magmatic intrusions in Krafla

and Bjarnarflag, and the formation of a steam cap in the Svartsengi field.

The highest emission for individual plants was recorded in 1980 when emissions from Bjarnarflag reached

569 g/kWh. In 1981, the highest emission values for Krafla were recorded at 297 g/kWh. High gas concentrations

in steam in Bjarnarflag and Krafla in the early 1980s resulted from influx of magmatic CO2 that was directly related

to the Krafla fires, volcanic events that started in 1975 and lasted until 1984 (Ármannsson et al., 2015). Since

1984, CO2 emissions from these two power plants have gradually decreased, with a few erratic exceptions.

In Svartsengi, CO2 emissions increased from 100 to 160 g/kWh in the late 1980s to 300 to 470 g/kWh in the mid-

1990s. Since 2000, the emissions from Svartsengi have gradually decreased and have now levelled off at around

100 g/kWh. The reason for the peak in CO2 emissions in Svartsengi in the 1990s was the increased production from

a steam cap that formed at shallow levels in the North East part of the field in the mid-1980s. The gas concentration

in the steam that formed in the steam cap was about an order of magnitude higher than in steam formed by flashing

geothermal brine in other parts of the field (5 wt% compared to 0.5 wt%; Bjarnason, 1996). Decreasing emissions from

Svartsengi in the last 15 years is a result of gradual decrease in CO2 concentration in the steam cap to less than 2 wt%

in recent years (Óskarsson, 2014) and of increased production from other parts of the reservoir relative to the steam cap.

B O X 2 . 1 ( C O N T I N U E D )

B O X 2 . 2

Thermal Decomposition of Carbonate Rocks

Carbonate rocks are common sedimentary rocks, composed mainly of calcite or aragonite (CaCO3) or dolomite

(CaMg(CO3)

2). Carbonate rocks are biogenic sedimentary rocks formed in relatively shallow waters from skeletal

fragments of marine organisms. Marble forms by recrystallization of carbonate rocks at high temperatures and

pressures, and is referred to as metamorphic carbonate rock.

When carbonate rocks are exposed to relatively high temperatures at relatively low pressure, such as near shallow

magma intrusions or in the roots of high temperature geothermal systems, the carbonate minerals react with silicates

to form calcium or magnesium silicates and CO2 gas. One example of such a thermal decomposition reaction is:

CaCO3 + SiO

2 = CaSiO

3 + CO

2

calcite + quartz = wollastonite + carbon dioxide

Thermal breakdown of carbonate rocks in the roots of geothermal systems can result in the formation of CO2 gas

that migrates up to the geothermal reservoir. Similarly, equilibrium between calcite, quartz, and wollastonite in high

temperature geothermal reservoirs can result in high concentrations of dissolved CO2 in the geothermal fluid.

11G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

composition (Arnórsson et al., 2007). Chemical reactions between CO2 in the geothermal fluids and

silicate and carbonate minerals may control the concentration of dissolved CO2 in the fluid, essentially

buffering the CO2 concentration in the reservoir fluid to a certain level at a given temperature.

These reactions are relatively slow to equilibrate and, as a result, the mineralogical control over the

concentration of dissolved CO2 in geothermal fluids does not always apply (i.e., the CO

2 concentration

in the reservoir fluid can in some cases be either higher or lower than dictated by the mineralogical

equilibria). Figure 2.1 shows a schematic diagram of a volcanic geothermal system illustrating the

different natural sources and sinks of CO2.

2.3. EFFECTS OF POWER PRODUCTION ON THE CO2 BUDGET OF GEOTHERMAL SYSTEMS

Extraction of fluid from high temperature geothermal reservoirs affects the balance between sources

and sinks of CO2 in a complex way that can evolve over time and space. The most important

processes are linked to steam cap formation, the effects of reinjection of gas-depleted brine after

F I G U R E 2 . 1

Natural Sources and Sinks of CO2 in a Volcanic Geothermal System

12C h a p t e r 2

power production, and the effects on surface activity (e.g., fumaroles, steaming grounds, etc.) as

illustrated in Figure 2.2.

2.3.1. Steam Cap Formation

Large scale removal of fluids as a result of geothermal power production may lead to reduced

pressure in the reservoir. The pressure decrease or “drawdown” lowers the boiling level5 in the

reservoir and increases the volume of the reservoir above the boiling level, resulting in increased

boiling. When this happens, the part of the reservoir above the boiling level becomes vapor

dominated. Because dissolved gases partition preferentially to the vapor phase, this process leads to

the formation of steam with relatively high gas concentrations while the reservoir liquid affected by this

F I G U R E 2 . 2

Volcanic Geothermal System Processes Affecting CO2 Emissions

13G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

boiling is left depleted of geothermal gas, including CO2, to some degree. This process, sometimes

referred to as a steam cap or steam zone formation, may result in increased gas concentrations in

steam from the steam cap but decreased gas concentrations in steam produced from the deeper,

liquid dominated part of the reservoir (c.f. Ármannsson et al., 2005; Glover and Mroczek, 2009). Steam

caps do not form in all geothermal systems and even when they do form, they may not have very high

gas concentrations.

Steam cap formation may have different effects on the gas concentration in the steam produced from

the reservoir, depending on the production strategy. The net effect of a steam cap formation on the

CO2 emissions from a given field will depend, to some degree, on the ratio of production from deeper

and shallower levels.

The gas concentration in steam caps may decrease with time. This has been observed in several

places such as in Svartsengi, Iceland (see Box 2.1), and Mount Amiata, Italy (Barelli et al., 2010).

These changes are gradual, occurring over years.

It is difficult to take these processes into account when assessing future emissions from a geothermal

power project. It is both difficult to predict whether a steam cap will form in a given reservoir and

how the gas concentration in the steam cap will evolve. Hence, this process should not be taken into

account when emissions are estimated, ex ante, in preparation of investment projects.

2.3.2. Impact of Reinjection

Reinjection of geothermal fluids after heat extraction is a common practice worldwide. Reinjection

started as a disposal method but is now recognized as an important tool for reservoir management

(Stefánsson, 1997; Kaya et al., 2011) as it helps maintain high reservoir pressures. Most commonly, the

reinjection liquid is separated geothermal brine with or without condensate. In some steam-dominated

reservoirs, surface waters are used for injection (Kaya et al., 2010).

In flash-steam geothermal power projects, the brine is separated from the steam phase. The gas

partitions into the steam phase and the brine is left effectively gas free. Only a very small fraction of the

gas dissolves in the condensate. The reinjected fluids (i.e., the brine and sometimes the condensate),

thus, are characterized by very low gas concentrations and will tend to dilute the reservoir fluid with

respect to dissolved gases. Injection management is an important issue in geothermal development.

Injection wells are located close enough to the production zone to provide recharge and pressure

support to the reservoir, but far enough from the production zone to allow the injected fluid to become

sufficiently heated on the way back to the production zone (driven by the pressure differential between

the injection zone and the production zone). Return of reinjected fluid may have a positive effect on the

gas concentration in the produced steam (i.e., resulting in gradual decrease of gas concentrations6 in

the geothermal reservoir fluid and lowering emission factors with time).

The relationship between reinjection and gas concentrations may be more complex in steam-

dominated reservoirs, even if the reinjected water is gas depleted. Reports from the Geysers field

in California indicate that gas concentrations in steam produced from different parts of the reservoir

14C h a p t e r 2

may either increase, decrease, or remain constant in response to injection of surface waters into the

reservoir (Klein et al., 2009; Beall et al., 2007).

As the available information on the effect of reinjection on gas content of geothermal reservoir fluids

is limited and not quite unequivocal, it cannot be assumed that gas concentrations in geothermal

reservoir fluids will decrease with time when future emissions from geothermal projects are assessed.

However, if more project data were available, it might be possible to make a rough estimate of how

the gas concentrations in geothermal fluids would evolve with time, particularly for projects using

reservoirs that are already in production.

2.3.3. Surface Activity

Pressure reduction in high temperature reservoirs due to production, as mentioned above, can lead

to increased boiling in the reservoir. Increased boiling in the reservoir, in turn, can lead to increased

surface activity. Examples of this are increased steam flow through fumaroles, increased soil

temperature, and increased extent of hot ground. This may be a common phenomenon but it has only

been quantitatively documented in a few places. So far, three studies have attempted to quantify the

effects of power production on geothermal surface activity in Wairakei and Ohaki, New Zealand (Allis,

1981; Rissman et al., 2012) and Reykjanes, Iceland (Fridriksson et al., 2010; Óladóttir and Fridriksson,

2015). In the Karapiti area in Wairakei, the surface heat flow (i.e., loss of heat through the ground-air

interface—heat loss can be used as a proxy for CO2 flow through the surface) increased by an order of

magnitude, from 40 MWt to 420 MWt, between 1958, when the first unit was commissioned, and 1964

(Allis, 1981). By 1978, the surface heat flow had declined to about 220 MWt and has not changed

significantly since then (Glover et al., 2001; Glover and Mroczek, 2009).

At Reykjanes, Iceland, a 100 MWe power plant was commissioned in 2006. Figure 2.3 shows

the evolution of the CO2 emissions from the Reykjanes system from 2004 through 2014. The CO

2

diffuse emissions through the soil were about 13 t/day in 2004 and 2005 but increased after the

commissioning of the power plant to 18.5 t/day in 2007 (Fridriksson et al., 2010, 2015). Since then, the

CO2 emissions through the soil have gradually increased to 51 t/day in 2013 (Óladóttir and Fridriksson,

2015). The CO2 emissions from the power plant have decreased by almost 25 percent from 2007

to 2014, but the total emissions from the system continues to increase because of the continuous

increase in diffuse degassing emissions.

Rissmann et al. (2012) reported a 70 percent increase in heat flow in the Western part of the Ohaaki

geothermal field in New Zealand after 20 years of production. No change in heat flow was noticed in

the Eastern part of the field. It, thus, can be concluded that the total increase in heat flow through soil,

and (by proxy) CO2 emission through soil from the system as a whole, was approximately 35 percent

over a period of 20 years. Increase in heat flow and CO2 emissions from the surface is likely to be

particularly pronounced in systems where the pressure drop is abrupt in response to production and

where the geothermal reservoir is connected to the surface (i.e., where geothermal manifestations are

abundant). Unfortunately, very few studies have allowed quantification of this effect.

15G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

In contrast to the above observations from Wairakei and Reykjanes, Bertani and Thain (2002) argue

that geothermal power production may actually cause a decrease in gas emissions through natural

pathways from geothermal reservoirs. Consequently, they argue that “a very strong case can be made

for subtracting the predevelopment natural emission rate from the rate being released by the operation

of the geothermal development” (p. 2). In support of this, they proffer that CO2 emissions through

natural pathways (i.e., soil and fumaroles) have noticeably and measurably decreased in Larderello

as a result of geothermal power production from that field. These observations of decreased surface

activity at Larderello are supported by pictures and descriptions from travelers that visited these areas

prior to development. According to these accounts, the entire Larderello area was covered by active

surface manifestations such as fumaroles, boiling pools, and steaming grounds, earning it the name

Devil’s Valley. Over the last several decades, power production from the Larderello system has brought

about pressure decrease in the reservoir and, as a result, the natural degassing from the system has

almost completely ceased (R. Bertani, personal communication). Similarly, Frondini et al. (2009), citing

Sammarco and Sammarco (2002), suggest that geothermal power production at Mount Amiata, Italy,

may have resulted in decreased natural gas emissions at that site.

F I G U R E 2 . 3

CO2 Emissions from the Reykjanes Geothermal System, Iceland

Note | Red curve show the combined emissions from power production (green) and diffuse CO2 degassing through surface

Source | Modified from Óladóttir and Fridriksson (2015).-

16C h a p t e r 2

Due to the limited number of studies that have directly measured the effect of geothermal power

production on CO2 emissions through natural pathways, it is not possible to make general statements

about the magnitude of this effect, which is likely to vary greatly from one site to another. It is also

possible that steam-dominated reservoirs respond differently to power production as compared to

liquid-dominated reservoirs as suggested for Larderello by Bertani and Thain (2002). The relationship

between emissions through soil and fumaroles and geothermal power production needs to be studied

in more locations in order to better understand the underlying processes. As a result, this effect should

not be taken into account when estimating future GHG emissions from geothermal power projects until

more data (based on direct CO2 flux measurements) become available.

ENDNOTES

3The 100-year global warming potential of CH4 relative to CO

2 is 25 (see Intergovernmental Panel on Climate Change,

IPCC: http://www.ipcc.ch/publications_and_data/ar4/wg1/en/ch2s2-10-2.html). This means that in terms of global

warming effect, each tonne of CH4 emitted is equivalent to 25 tonne of CO

2. Emissions of CH

4 are commonly

presented in terms of grams carbon dioxide equivalent per kilowatt hour (gCO2e/kWh).

4CH4 emissions from the Reykjanes and Svartsengi power plants in Southwest Iceland range from 0.1 to 0.25% of

the total GHG emissions (Óskarsson et al., 2014; Óskarsson, 2013), whereas the contribution of CH4 to the total

GHG emissions from the nearby Hellisheidi and Nesjavellir power plants are of the order of 1.5 to 4% and 3 to 9%,

respectively (unpublished data from Reykjavik Energy). Data from New Zealand (New Zealand Ministry for the

Environment, 2013), show that CH4 accounted about 16% of the total CO

2 equivalent emissions from geothermal

power plants in that country in 2012. The CH4 content in terms of CO

2 equivalents (computed from 15 gas analyses

referred to in Table 2.1) range from 0.1 to 30% of the total GHG content with a median value is 3.7%.

5The boiling level in a geothermal reservoir is the depth at which the liquid is in equilibrium with water. Below the

boiling level, the reservoir fluid is liquid but liquid and vapor coexist above the boiling level.

6Benoit and Hirtz (1994) reported that gas emissions from the Dixie Valley power plant in Nevada, USA, decreased

from 69 g/kWh in 1988 to 42 g/kWh in 1992 as a result of returning reinjection water to the production wells. The

same has occurred in Kizilidere, Turkey, where the CO2 concentration in the reservoir fluid decreased by 15% from

1984 to 2000 (Haizlip et al., 2013). Similarly, Glover and Scott (2005) report 16 to 30% decrease in CO2 content of

the reservoir fluid in Ngawha, New Zealand, due to reinjection after only 6 years of production.

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G H G E M I S S I O N S F R O M G E O T H E R M A L P O W E R P L A N T S

Life cycle analyses (LCA) are being used increasingly to assess emissions from power projects

(among many other infrastructure projects). According to the LCA approach, emissions are assessed

for the plant cycle and fuel cycle separately. In the context of geothermal projects, the plant cycle GHG

emissions include emissions related to the construction of the power plant and surface installations,

drilling and completion of wells, the production of the materials needed for these installations, and

the eventual decommissioning of the facilities, normalized over the lifetime of the project. Plant cycle

emissions are referred to as upstream and downstream emissions in the World Bank Guidance Manual

for GHG accounting (World Bank, 2015). The fuel cycle emissions refer, in the case of geothermal

projects, to the release of geothermal GHGs during the energy conversion process. The fuel cycle

emissions are sometimes referred to as “operational” or “fugitive” emissions. Most of the available

literature on GHG emissions from geothermal projects refers to the fuel cycle emissions only and only

a handful of relatively recent publications have addressed the plant cycle emissions from geothermal

power production. This is reflected in the discussion below which is largely focused on operational

emissions.

3.1. ASSESSMENTS OF PLANT CYCLE GHG EMISSIONS FROM GEOTHERMAL PROJECTS

The available information on plant cycle emissions indicate that plant cycle emissions are in the range 2

to almost 20 gCO2e/kWh, assuming a project lifetime of 30 years. Sullivan et al. (2013) estimate that

the plant cycle emissions for a hypothetical 50 MW flash plant in Southwest United States would be in

the range 2 to 5 gCO2e/kWh and their estimate for a 10 MW binary plant in the same location was 5 to

6 gCO2e/kWh. The numbers are in agreement with the results of Marchand et al. (2015) who estimated

plant cycle emissions for three expansion scenarios for the Bouillante geothermal field in Guadeloupe

to be in the range from 3.8 to 5.2 gCO2e/kWh. Karlsdóttir et al. (2015) estimated that plant cycle

emissions from the Hellisheidi plant in Iceland would be of the order of 8.4 to 10.8 gCO2e/kWh. The

highest value reported for plant cycle emissions is from Hondo (2005) with 15 gCO2e/kWh. However,

Hondo assumed a capacity factor of only 0.6 for his hypothetical plant. If a more realistic value of 0.9

is used for the capacity factor, then the resulting life cycle emission is 10 gCO2e/kWh. Finally, Rule et

al. (2009) reported a plant cycle emission value of 5.6 gCO2e/kWh for the geothermal power plant in

Wairakei, New Zealand. However, this value corresponds to a project lifetime of 100 years. When Rule

et al.’s (2009) value is converted to a basis of a 30-year lifetime the resulting plant cycle emission value

could be as high as 18.6 gCO2e/kWh.

Although the above data are too scarce to derive a statistically significant mean or median value for

plant cycle GHG emissions from geothermal power projects, the range of the values estimated in

the different studies is relatively small. Considering the range and the magnitude of operational GHG

emissions from geothermal projects (see sections 5.2 and 5.3) it is acceptable, for the purpose of this

18C h a p t e r 3

Interim Technical Note, to assume that plant cycle GHG emissions of geothermal power projects are

equal to 10 gCO2e/kWh for a standard project lifetime of 30 years. While the data presented by Sullivan

et al. (2013) and Marchand et al. (2015) are significantly lower than 10 gCO2e/kWh, the difference—

amounting to some 5 gCO2e/kWh—is insignificant in the context of the overall GHG emissions from

geothermal power projects.

3.2. GLOBAL AND NATIONAL SURVEYS ON OPERATIONAL GHG EMISSIONS

The most complete global survey on CO2 emissions to date was presented by Bertani and Thain (2002).

Their study was based on emissions and power production information from 85 geothermal power

plants in 11 countries, with a combined installed capacity of 6,648 MW, roughly 85 percent of the global

geothermal power capacity in operation in 2001. The power plants included in the 2001 global study

still amount to more than 50 percent of the total installed capacity today and can be considered a fairly

reliable indicator of the range and global average of CO2 emissions from geothermal power plants. The

study found that the range of CO2 emissions from geothermal power generation was from 4 to 740 g/kWh,

and the weighted average was found to be 122 g/kWh. Emissions from binary plants were not included in

these numbers (Bertani, personal communication 2014). Also, it should be noted that the survey focused

exclusively on CO2 emissions; CH

4 emissions were not considered. The results of this global survey are

presented in a short article in IGA News with very limited details, however, they are supported by CO2

emission data available from different countries.

Bloomfield et al. (2003) reported an estimate of CO2 released from power plants in the United States.

The reported average emission of CO2 was found to be 91 g/kWh. Bloomfield et al. (2003) state that

non-emitting binary plants amounted to 14 percent of the total capacity of the plants included in their

study. The CO2 emissions from the remaining 86 percent of the plants (i.e., the flashing steam and dry

steam plants) can then be computed to be 106 g/kWh.7 Recent data on CO2 emissions and power

generation of geothermal power plants in California (California Air Resources Board, 2014; US DOE,

2014) allow calculation of CO2 emission factors for some plants from 2011 to 2013. The results show a

fairly wide range of factors. In 2013, the highest CO2 emission factors were at the three power plants

at Coso, ranging from 150 to 300 g/kWh with a weighted average of 245 g/kWh. CO2 emissions from

the Geysers power plants in 2013 were more moderate, ranging from 41 to 76 g/kWh with a weighted

average of 45 g/kWh.

Data presented in New Zealand’s Sixth Communication to the United Nations Framework Convention

on Climate Change and the Kyoto Protocol (2013) allow calculation of CO2 equivalent emissions from

the country’s geothermal power plants in 2012 at 122.7 gCO2e/kWh. Of these emissions, 104.4 g/kWh

are due to CO2 and the remaining 18.3 gCO

2e/kWh correspond to CH

4 emissions.

Baldvinsson et al. (2011) presented data for CO2 emissions from all the Icelandic geothermal power

plants from 1970 to 2009 (see Box 2.1). The weighted average CO2 emissions from the six power

plants in 2009 was 50 g/kWh, with a range of 21 to 92 g/kWh. Emission factors have decreased slightly

in recent years. According to emission data provided by Icelandic geothermal power producers, in

2013, CO2 emission factors ranged from 18 to 78 g/kWh and the weighted average was 34 g/kWh.

19G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

Again, these numbers represent CO2 emissions only; CH

4 emissions are not taken into account.

Available CH4 emission data from four out of six geothermal power plants in Iceland suggest that CH

4

emissions could amount to 5 percent of GHG emissions from Icelandic geothermal power plants on a

CO2 equivalent basis.

CO2 emissions from Italian geothermal plants are generally rather high. Emission factors for power

plants in Larderello, Mount Amiata, Val di Cornia and Travale-Chiusino were computed from data from

the Regional Environmental Protection Agency for Tuscany (ARPAT, 2012, 2013). Data were available

for 2002 to 2013. In this period, the weighted average CO2 emission factors decreased gradually from

422 to 330 g/kWh. In 2013, CO2 emission factors ranged from 114 to

827 g/kWh and the weighted average was 330 g/kWh.

3.3. HIGH EMISSION OUTLIERS

The highest value for geothermal CO2 emissions reported by Bertani and Thain (2002) was 740 g/

kWh. Bertani and Thain did not report standard deviation of emission factors for the plants observed

included in their global survey. However, according to Bertani (personal communication, 2016), the

standard deviation of the emission factors was substantial at 163 g/kWh, suggesting that there were

already several geothermal power plants with significant GHG emissions in 2002. Since then, new

emissions data from several high emission geothermal power plants have become available. Below,

two well reported examples in West Turkey and in Mount Amiata, Italy, of high emission geothermal

power plants are described. Other high emissions geothermal systems exist, such as the Ngawha

system in New Zealand,8 but there is limited information on the geological and physical conditions in

the Ngawha reservoir. What the high CO2 systems in Turkey and Italy systems seem to have in common

is that they are hosted in carbonate-bearing rocks, although anomalous deep mantle CO2 may also

contribute to the high values in Mount Amiata.

3.3.1. Buyuk Menderes Graben, Western Turkey

Aksoy (2014) published CO2 emission factors for nine power plants in seven geothermal fields in

Turkey. The emission factors range from 400 to 1,300 g/kWh and the weighted average (based on

installed capacity) is 1,050 g/kWh. Eight of the nine power plants considered by Aksoy (2014) are

located in the Menderes graben where most of the feasible geothermal resources for power production

in Turkey have been identified (Basel et al., 2010). The range of emissions from the Buyuk Menderes

graben power plants is from 900 to 1,300 g/kWh (Aksoy, 2014; Haizlip et al., 2013; Wallace et al,

2009). The second most developed region for geothermal power production in Turkey is the Gediz

graben, located north of the Buyuk Menderes graben, and preliminary information indicate that CO2

emissions will be similar to those from the Buyuk Menderes graben. It should be noted that not all the

CO2 brought to surface by geothermal production in Turkey is released directly into the atmosphere. In

at least two of the Turkish geothermal power plants, the CO2 from the geothermal fluid is captured and

sold off as dry ice and liquid CO2.

20C h a p t e r 3

The high gas emissions from the geothermal power plants in Buyuk Menderes and Gediz grabens are

a result of unusual geological settings. Most of the high temperature geothermal fields in the country

are located in the Aegean region in Western Anatolia (Basel, 2010). This area is characterized by

extensional tectonics, resulting in graben formations and crustal thinning (Haizlip et al., 2013). High

regional heat flow, resulting from crustal thinning appears to be the main source of heat for these

geothermal systems (Aksoy et al., 2015; Haizlip et al., 2013). This region is also characterized by

an abundance of carbonate sedimentary and metamorphic rocks, such as limestone and marble.

The high concentrations of CO2 in the geothermal fluids in the region seem to result from thermal

breakdown of carbonate minerals in the reservoir rocks (Aksoy et al., 2015; Haizlip et al., 2013).

3.3.2. Mount Amiata, Italy

The geothermal power plants at Mount Amiata, Italy, provide another example of very high gas

emissions. Bravi and Basosi (2014) report CO2 and CO

2 equivalents emissions from the Bagnore

and Piancastagnaio power plants from 2002 to 2009. The range of CO2 emissions from the two areas

was from 245 to 779 g/kWh and the weighted average was 497 g/kWh. The average value for CO2

equivalent emissions was 693 g/kWh and the range was 380 to 1,045 g/kWh.

Mount Amiata is a Quaternary volcano in southern Tuscany. It is thought that a granitic intrusion related

to the volcano is the heat source for the two geothermal fields that occur on the South West and South

East flanks of the volcano (Haizlip et al., 2013). Both systems consist of a shallow reservoir with a very

gas-rich steam cap and hot (>300°C) deep reservoir. Carbonate rocks are common in the shallow

reservoir and exist, to some extent, in the deep the reservoirs of both systems and likely contribute to

the high gas concentration in the geothermal fluids (Frondini et al., 2009; Haizlip et al., 2013). However,

δ13C isotope data suggest that a significant fraction of the CO2 in the geothermal reservoirs originates

in the mantle (Frondini et al., 2009). Deep mantle degassing occurs on a regional scale under large

parts of Italy (Gambardella et al., 2004).

ENDNOTES

7This study does not report the range of emissions from the United States plants nor the total number of plants and

their capacity. It is implied that all geothermal power plants in the United States are included, with a total installed

capacity of 2,500 MW at the time (Lund et al., 2005).

8The New Zealand Geothermal Association reports an emission factor of 597 g/kWh for the Ngawha power plant

(http://www.nzgeothermal.org.nz/emissions.html).

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T E C H N I C A L O P T I O N S T O M I T I G A T E C O2 E M I S S I O N S

F R O M G E O T H E R M A L P O W E R P L A N T S

4.1. ENERGY CONVERSION TECHNOLOGIES AND CO2 EMISSIONS

The four basic types of energy conversion technologies used for geothermal power production are

described in Box 4.1. These are back pressure plants, condensing plants,9 two-phase (flashing) binary

plants, and single-phase (pumped) binary plants. Power plants where two or more power cycles

are combined are referred to combined cycle power plants.10 Condensing plants constitute about

84 percent of the worldwide installed capacity of geothermal power plants whereas binary plants

amount to 15 percent of the total installed capacity (GEA, 2015). Up to date information on the market

share of Single-phase binary plants versus flash binary plants are not available, but as of August 2011,

two-thirds of all binary plants were single-phase plants (DiPippo, 2012). Back pressure plants, the most

simple but also the most inefficient type of geothermal power plants, amount to only 1 percent of the

global installed capacity (GEA, 2015). All of these technologies, with the exception of the single-phase

binary, emit effectively all the CO2 in the produced geothermal fluid to the atmosphere.

The selection of energy conversion process for a particular geothermal project depends on a number

of parameters, such as resource temperature, pressure, flow rate, and chemical content. The main

difference between processes using steam (back pressure, condensing, two-phase binary) and a

liquid (single-phase or pumped binary) is the different driving forces for the flow of the geothermal

fluid from the wells to the plant. In the steam processes, the driving force is the pressure difference

between the resource and inlet at the power plant. Therefore, no pumping is needed. For single-phase

(pumped) binary process, deep well pumps are usually needed.

In single-phase binary plants, the fluid pressure needs to be kept high enough to prevent the formation

of a gas phase throughout the process from extraction of the fluid, through the heat exchange process

and, eventually, reinjection. This poses two challenges for production from high temperature gas-rich

geothermal fluids. Firstly, downhole pumps designed for high temperatures are expensive and their

longevity is constrained at high temperatures (Verkís Consulting Engineers, 2015). And secondly, the

higher the gas content in the fluid, the higher the pressure that needs to be maintained throughout

the system in order to prevent phase separation. Consequently, if emission of gas from gas-rich fluids

is to be prevented in pumped binary plants, the pumping may consume a considerable fraction of

the power generated.11 The general resource temperature ranges suitable for the different energy

conversion technologies are shown in Table 4.1.

High gas content in geothermal fluid suppresses the boiling point and causes the geothermal fluid

to flash at lower temperatures than gas-poor fluid. As a result, in high gas systems, the maximum

temperature for pumped binary and the minimum temperature to flashed binary are lowered (see Box 4.1).

The pressure and temperature conditions of the NCG after the energy conversion cycle are different,

depending on the energy conversion technology. The NCG exits the heat exchangers of flash binary

22C h a p t e r 4

B O X 4 . 1

Energy Conversion Systems and Non-Condensable Gas Emissions

Below is an overview of different conversion technologies and how they affect CO2 emissions from geothermal

power production. Simple process diagrams are used to illustrate the flow of different fluids through the systems

with special emphasis on the fate of the NCGs.

(continued)

Back Pressure Turbine

In a back pressure turbine, the geothermal fluid is flashed in a separator, the steam and NCG are admitted to

the turbine, and exhausted through the chimney at atmospheric pressure. Back pressure turbines comprise

only 1% of the global geothermal power production capacity.

Single-Flash Condensing Plant

The main difference from the back pressure unit is the addition of a specialized cooling system consisting of a

condenser and a cooling tower. This is done to increase the pressure drop over the turbine in order to increase the

power output from the turbine and improvement of the overall system efficiency.

23G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

B O X 4 . 1 ( C O N T I N U E D )

Single-Flash Condensing Plant (continued)

In a direct cooling condenser, it is necessary to have a specialized gas removal system. The steam and NCGs

are cooled directly with a spray of cold water. Most of the steam is condensed there and sinks to the bottom of

the condenser as liquid. The NCGs and some of the steam are not condensed. This mixture of low pressure gas

and water vapor will have to be removed with a specialized gas removal system to prevent pressure build up in

the condenser, which would cause a decrease in the production capacity of the turbine. There are two commonly

used types of gas removal devices—ejectors and liquid ring vacuum pumps. The gas is extracted from the

condenser and either vented into the atmosphere via the chimney or the cooling tower fan stacks.

A surface (indirect) condenser instead of a direct cooling condenser can also be used. The same principles

apply for a surface condenser as a direct condenser; the gas will have to be removed to prevent build-up of

NCGs and, then, will be exhausted through a cooling tower or a chimney.

Flash condensing plants can also be double, or even triple, flash. The same applies for these plants as for

single flash plants; the NCGs have to be removed through a cooling tower or chimney.

Two-Phase Binary Power Plant

In a two-phase binary power plant, the geothermal fluid is flashed in a separator. The steam and NCGs are

used to boil the working fluid in the vaporizer. The design shown involves a preheater where the brine is used

to heat the working fluid before it enters the vaporizer. Another common design is to have brine and steam both

enter the vaporizer directly but keeping them separated through the process. As the steam passes through the

vaporizer, it condenses and the NCGs are vented out of the vaporizer to prevent pressure build-up. The NCG

exits the vaporizer at a pressure near the inlet pressure of the steam, commonly 3 to 5 bar-g.

(continued)

24C h a p t e r 4

B O X 4 . 1 ( C O N T I N U E D )

Single-Phase (Pumped) Binary Cycle Power Plant

In a typical single-phase binary power plant, the geothermal fluid is kept in liquid phase throughout the entire process. Usually, the

geothermal fluid will have to be pumped from the well, but in exceptional cases, the well head pressure is high enough for the well to be

self-flowing. To keep the NCGs in the liquid, it is necessary to maintain high pressure through the heat exchanging process. It is also

a possible to use chemical inhibitors to avoid precipitation of minerals such as calcite that can clog equipment and wells, resulting in

additional repair costs. Full reinjection and “zero-emission” is possible for this cycle. If gas emission is to be prevented, the operating

pressure needs to be kept high enough to prevent the NCGs from coming out of solution. The NCGs can be vented from the heat

exchanger if reinjection is not preferred.

Source | This box draws on materials prepared for this paper by were prepared by Verkís Consulting Engineers, an engineering company.

25G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

plants at a pressure roughly equal to the inlet pressure of the heat exchanger, typically 3 to 5 bar-g

and at a temperature generally below 70°C. The gas exits from combined cycle (back pressure-binary)

plants at about the same temperature (<70°C) and about 1 bar-a at temperature. The NCG exits back

pressure plants and most condensing plants as steam at atmospheric pressure and near 100°C. As a

result, the NCG stream coming from a flash binary plant is better suited for capture and processing as

it comes out under pressure and with a much lower content of water vapor compared to the NCG from

condensing and back pressure plants (Verkís, 2015).

4.2. GAS SEQUESTRATION TECHNOLOGIES

There are several technologies that have been developed to capture and treat NCGs from geothermal

power plants. Most of these have been developed to remove H2S from the geothermal gas released to

the atmosphere but there are also a few examples of geothermal CO2 capture (Mamrosh et al., 2014).

Geothermal CO2 is captured at some of the geothermal power plants in Turkey, including Kizildere, Dora I

and II, and Gumuskoy (c.f. EBRD, 2016). The gas captured at these power plants is commercialized

for dry ice production and for production of carbonated beverages (Aksoy, 2014; Simsek et al., 2005).

Geothermal CO2 can also be used to enhance photosynthesis in green houses, production of paint and

fertilizer, fuel synthesis, and for enhanced oil recovery (Trimeric Corporation, 2015; Verkís Consulting

Engineers, 2015).

It is possible to reinject some or all of the NCG from geothermal plants. This is not widely practiced

but two notable example are available. Near complete NCG reinjection is practiced at the Puna plant

in Hawaii (Yoram Bronicki, personal communication 2016). Similarly, since 2014, Reykjavik Energy has

reinjected about a quarter of the geothermal H2S and about 10 percent of the CO

2 from the Hellisheidi

Power Plant in Southwest Iceland (Ingvi Gunnarsson, pers. comm., 2016).12

The cost and economic feasibility of CO2 capture from geothermal NCG depends on several factors.

These include the NCG composition, the pressure of the NCG at the outlet from the power plant, and

the desired purity and pressure of the end product (Mamrosh et al., 2014), as well as the size of the

T A B L E 4 . 1

Resource Temperature Ranges Suitable for the Different Energy

Conversion Technologies

PLANT TYPE < 150°C–180°C 180°C–200°C 200°C–220°C > 220°C

Single-Phase (pumped) Binary 150°C applies if deep pumping is needed

Two-Phase (flash) Binary

Combined Cycle (back pressure/binary)

Flash Condensing

Back Pressure

26C h a p t e r 4

demand relative to the volume produced. The cost of capturing and processing CO2 can be estimated

from a hypothetical geothermal power plant.13 Assuming that 1,200 t/day of CO2 rich NCG is captured,

this would correspond to the daily emission from a 50 MW power plant with an emission factor of 1,000

g/kWh or from a 100 MW power plant with an emission factor of 500 g/kWh. Details of this assessment

are shown in Box 4.2. The estimated cost of capturing and treating the gas ranged from about $5/t

CO2 for low pressure gas for green house applications up to about $23/t CO

2 for liquefied, beverage-

B O X 4 . 2

Estimated Cost of CO2 Capture and Treatment

The cost of capturing and processing NCG is estimated for a fluid with relatively high CO2 content (98.4% by

volume), moderate concentrations of N2, CH

4, H

2S, and NH

3 (0.5, 0.7, 0.2 and 0.1% by volume, respectively) and trace

concentrations of H2 and Ar (0.05 and 0.005% by volume, respectively). The assessment considered only commercially

available and tested technologies. The total NGC supply was taken to be 50 t/hr. To put this gas supply into perspective,

50 t/hr corresponds to emissions from a 50 MW power plant with an emission factor of 1,000 g/kWh or a 100 MW

power plant with an emission factor of 500 g/kWh. Furthermore, it is assumed that that the NCG was delivered to the

treatment plant saturated with water vapor at 70°C and 4 bar-g. This corresponds to conditions at a two-phase binary

plant, which is the most suitable technology when the gas content of the geothermal fluid is high. Treatment of gas from

the more conventional condensing power plants will be generally similar to the case considered with two exceptions:

(i) O2 removal will need to be included in the treatment of gas from condensing power plants; and (ii) more compression

will be needed as the gas exiting the condenser will be at lower pressure compared to the gas from the binary plants.

The gas treatment cost depends strongly on the intended use of the captured gas. To this end, there are four uses to

consider, two of which have more than one treatment option, depending on the presence of trace gases:

• Low pressure gas for use in greenhouses with or without Hg removal. The basic case involves

the removal of NH3, H

2S, and H

2O. Bulk removal of NH

3 (to 40 ppmV) is assumed to be achieved by

ammonia dissolution in the condensate water. Liquid Redox Sulfur Recovery (LRSR) technology will reduce

the H2S concentration to less than 1 ppmV and finally, H

2O is removed from the gas by condensation by

cooling the gas to 7.2°C. Additionally, the cost of Hg removal is considered separately as this may not be

necessary in many cases. A 5 km pipeline is included in the cost estimate for the greenhouse application.

• Supercritial CO2 compressed to 125 bar for Enhanced Oil Recovery. For this purpose, it is

necessary to reduce the concentration of NH3 to less than 0.1 ppmV in order to prevent the formation of

solids during the compression of the gas. This can be achieved by dissolution of NH3 in condensate water

during chilling, followed by acid scrubbing. The same LRSR process for H2S removal is anticipated as for

the low pressure gas for greenhouse application. H2O is removed from the gas through a combination of

compression and chilling and glycol dehydration. The pipeline cost is not included in the cost estimate.

• Liquefied beverage-grade CO2 (with and without removal of Hg, COS, and C

2H

6). It should be noted

that the cost estimate for the liquefied beverage-grade CO2 also applies to food-grade, dry-ice grade,

and industrial-grade CO2. The basic case involves the removal of H

2S, NH

3, H

2O, N

2, Ar, H

2, and CH

4.

Furthermore, the additional cost of removing the trace gases Hg, COS, and C2H

6, which may or may not

need to be removed to meet the standard for beverage-grade CO2, is also considered. In this case, NH

3 is

(continued)

27G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

removed through a combination of compression and chilling and acid washing down to a concentration

of less than 0.1 ppmV. The concentration of H2S is reduced to less than 0.1 ppmV through a combination

of an LRSR process at low pressure and solid scavenger process at 22 bar pressure. H2O is removed

through condensation and molecular sieves down to concentrations of less than 1 ppm. The more

volatile gases (N2, Ar, H

2, and CH

4) are removed through fractional distillation of the liquefied fluid. The

cost of four 500-ton storage tanks for CO2, is included in the capital cost estimate for the beverage-grade

CO2. In addition, the cost of removing Hg, COS, and C

2H

6 is estimated for each gas species.

• Reinjection of NCG along with brine and condensate. The cost of reinjecting the NCG back into the

geothermal reservoir along with a mixture of brine and condensate from the power plant is then estimated. It

is estimated that the 50 t/hr of gas would be dissolved in 2,500 t/hr of geothermal liquid at 70°C and 55 bar

pressure should be sufficient to dissolve the gas in the liquid at this temperature. This corresponds to about

560 m depth in a well full of water at 70°C or well above the typical depth of geothermal reservoirs (1,000

to 1,500 m). In order to prevent the formation of solids, it is necessary to remove the NH3 from the gas

stream before it is compressed. This is achieved by dissolution in condensate and acid washing as for the

supercritical CO2 for enhanced oil recovery (EOR) and the beverage-grade CO

2. The gas is then compressed

to 55 bar and pumped into a reinjection well along with brine and condensate.

Cost Assessment of Non-Condensable Gas from Geothermal

Power Plants, by Use

PRODUCT GAS SPECIES REMOVED

CAPITAL COST1

POWER USAGE

TOTAL OPERATING COST

CAPITAL AMORTIZATION1

TREATMENT COST PER PRODUCT

$1,000s MW $1,000/yr $1,000/yr $/tCO2

Greenhouse

CO2

H2S, NH

3,

H2O

13,122 0.21 1,364 656 5.00

Hg 634 0.00 74 31.7 0.25

Total 13,756 0.21 1,437 688 5.24

CO2 for EOR H

2S, NH

3,

H2O

25,304 3.70 4,972 1,265 15.40

Beverage-

grade CO2

H2S, NH

3,

H2O, N

2, H

2,

Ar, CH4

37,793 4.60 6,641 1,890 21.10

Hg 634 0 74 31.7 0.25

COS 372 0 51 18.6 0.16

C2H

64,230 0.15 421 211.5 1.47

Total 43,029 4.80 7,187 2121.0 23.00

Reinjection

of CO2

NH3

14,700 3.20 3,443 735 10.30

1Includes 20% contingency

Source | Trimeric (2015).

B O X 4 . 2 ( C O N T I N U E D )

28C h a p t e r 4

grade CO2. Trimeric (2015) estimated that the cost of gas reinjection would be $10.3/t CO

2

14. These

costs are inclusive of capital cost,15 operation and maintenance, and power consumption.16 The power

consumption for the GHG applications is modest at 0.2 MW, whereas food-grade purification and

subsequent liquefaction will consume about 4.8 MW (Trimeric Corporation, 2015).

The gas capture and treatment costs are highly dependent on site specific conditions, such as the

total gas flow (in t/h), the gas to liquid ratio, and the composition of the NCG. The gas composition

considered by Trimeric (2015) is representative for high CO2 geothermal systems where the NCG

consists of nearly pure CO2. The treatment cost for more typical geothermal NCG compositions,

characterized by higher H2S/CO

2 ratio, is likely to be higher than the Trimeric estimates. However, NCG

capture and treatment may not be relevant for the vast majority of geothermal power plants where

GHG emissions are low.

Another important factor to consider in this context is the capacity of the market to absorb geothermal

CO2 products. A study commissioned by EBRD (2016) on the market conditions for geothermal CO

2 in

Turkey indicates that the market for beverage-grade CO2 in Turkey is near saturation with the existing

gas capture plants at Kizildere, Dora I, and Gumusköy. Market conditions, thus, may pose more

significant constraints on CO2 capture from geothermal power plants than the technology.

ENDNOTES

9Condensing plants can use either flash steam or dry steam, depending on the nature of the geothermal resource.

10Combined cycle plants, where the steam is first passed through a back pressure unit and then to a binary plant,

are suitable for gas-rich systems.

11Pumping consumes power in all pumped binary geothermal power plants. However, in order to prevent gas

release from gas-rich fluids, it may be necessary to operate the power plant at a pressure above the “bubble

point” of the fluid (i.e., the pressure at which the gas separates from the water at a given temperature). Raising the

operating pressure of the power plant above the bubble point pressure requires additional pumping power.

12For a detailed analysis on technical options for CO2 capture and use and economical and market-related

constrains the reader, see the abovementioned report from EBRD (2016).

13The estimate is based on calculations prepared for this paper by Trimeric Corporation, a chemical engineering

company.

14Reinjection cost is highly sensitive to the gas to liquid ratio in the reinjection stream. In gas-rich systems, such as

the hypothetical system in the case considered here, relatively high pressure is needed to dissolve the gas in the

liquid during reinjection with direct implications for cost due to power consumption and more expensive equipment.

15Assuming 20 years amortization.

16Assuming a cost of $0.105/kWh.

29

5

G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

A S S E S S I N G G H G E M I S S I O N S F R O M

G E O T H E R M A L P O W E R P R O J E C T S

This section is intended to supplement the existing Guidance Manual on Greenhouse Gas Accounting

for Energy Investment Operations (World Bank, 2015), which outlines the methods used to assess

GHG emissions and emission offsets from power projects over the project life time. A fundamental

parameter for that assessment is the default GHG emission factor for a given energy source. The

Guidance Manual defines the default emission factors based on operational emissions over a project

life time. The plant cycle emissions (i.e., upstream and downstream emissions by the Guidance

Manual terminology) are defined as scope 3 emissions and their inclusion in the emission estimate

for a given project is optional (World Bank, 2015). The objective of this Interim Technical Note is to

suggest methodologies to predict or estimate the appropriate GHG emission factors for geothermal

power projects at different stages of development. In the subsequent sections, the term “emission

factors” is used to refer to operational emissions only.

Figure 5.1 shows the range of GHG emission factors for geothermal power compared to emission

factors for power generation using fossil fuels. The figure illustrates that the emission factors from

geothermal power plants span a wide range. Although the global weighted average emissions from

geothermal power plants—122 g/kWh—is still significantly lower than from fossil fuel plants, in some

cases, GHG emissions from geothermal power plant can be high, or up to 1,300 g/kWh in the most

extreme case reported. Thus, it is imperative that GHG emissions are assessed in any World Bank-

financed geothermal power project.

The accuracy of the estimated GHG emission factors in geothermal power projects will depend

significantly on the nature and the quality of the existing information. It is necessary to use the

most recent data available and to update the emission estimates as new data become accessible.

This applies both to projects that are being developed and to projects already in operation as

experience has shown that emission factors from geothermal power plants can change significantly

over time. Emission factor estimations should be conservative in order to prevent underestimation on

future emissions.

In the following sections, methodologies for assessing GHG emission factors for geothermal projects

are presented. (See Box 5.1 for a definition of the phases of geothermal development.) Different

approaches need to be taken for this assessment depending on the maturity of the project under

consideration. The project maturity levels considered are:

1 | Greenfield projects - projects that are in the very early stages of development

2 | Brownfield projects - projects that are in capacity drilling phase or capacity expansion

projects in fields where power plants are already operating

3 | Projects involving existing power plants

PA

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30C h a p t e r 5

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31G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

5.1. ESTIMATING EMISSION FACTORS FROM GREENFIELD PROJECTS

The term “greenfield geothermal project” refers to projects in the exploration phase in a geothermal

systems that is not under production, which includes projects from the initial reconnaissance work until

the exploration drilling phase has been completed. As a result, the nature of the information available

to estimate the GHG emission factor can differ considerably; from virtually none to observed reservoir

temperatures and measured gas concentrations in steam or total fluid from exploration wells. The

approach taken to estimate the GHG emission factor for a project will then depend on the nature of

the available data. The different approaches are described schematically in Figure 5.2 and further

elaborated in the subsequent sections.

5.1.1. Greenfield Projects Where No Wells Have Been Drilled

Estimated project emission factors prior to drilling will always be highly uncertain. However, it may be

possible to arrive at rough estimates to be used until drilling has provided better insights into the GHG

content of the geothermal fluids.

If the geothermal project in question does not have any neighboring projects or if emission data are

not available from neighbors, the general geology of the area should be used to guide estimates of

emission factors. If there is no available information on the subsurface lithology or if the geological

information indicates that the geothermal resource is hosted in volcanic rocks, the most appropriate

proxy for the future GHG emission factor is the global average CO2 emission factor—122 g/kWh. In

order to account for potential GHG contribution from CH4 for projects where the gas composition is

not known, it should be assumed that CH4 constitutes 5 percent of the GHG emission in terms of CO

2

equivalents, resulting in an assumed emission factor of 128 gCO2e/kWh.

B O X 5

Phases of Geothermal Development

The development of a geothermal power project is commonly divided in the four phases summarized below:

1 | Exploration Phase. This phase establishes the location, size, and quality of the geothermal reservoir;

activities conducted include surface exploration, followed by exploration and confirmation drilling.

2 | Resource/Field Development Phase. This phase includes the drilling of the wells which will be

used to mobilize the geothermal resource from the reservoir and confirm the precise volume available for

commercial energy production; activities conducted are capacity drilling (also called production drilling).

3 | Power Plant Development Phase. This phase consists of the final design, procurement, and

construction of the power plant that utilizes the geothermal energy identified in Phase II, including steam-

gathering systems, power house, and equipment to connect the power plant with the electricity grid.

4 | Facility Operations Phase. This phase includes the operation and maintenance of the steam-

gathering systems and the power plant.

32C h a p t e r 5

Exis�ng geothermal power plants in analogous geological se�ng

Explora�on wells drilled and discharge tested; pumped binary not feasible

Carbonate rocks expected at reservoir level

unless

Compute an an�cipated emission factor from (i) the average GHG concentra�on in steam or total fluid, weighted by well produc�vity and (ii) the an�cipated steam or fluid consump�on factor for the selected energy conversion technology (see Box 5.2)

Use GHG emission factors from neighboring / analogous power plants, if available and if geological condi�ons are comparable

An�cipate high GHG emission factors – 790 gCO2e/kWh

As a default, assume GHG emission factors are equal to the global weighted average CO2 emission factor, 128 gCO2e/kWh

Available Informa�on Es�ma�on of GHG Emission Factor

Pumped binary technology an�cipated Assume emission factor of 0 gCO2e/kWh

No informa�on on geology or energy conversion technology OR volcanic rocks

expected at reservoir level

or

or

or

F I G U R E 5 . 2

Approaches to Define GHG Emission Factors from Greenfield Geothermal Projects

If, however, there is a reason to believe that carbonate rocks are present at reservoir level in a given

system, it is appropriate to expect high GHG emission factors for the project. Observed CO2 emission

factors in the Aegean region in Turkey and Mont Amiata in Italy suggest that it would be reasonable

to expect CO2 emissions in the range from 500 to 1,000 g/kWh from projects in carbonate-hosted

high temperature systems. It is suggested that in such situations the midrange value, 750 g/kWh, is

used (Bertani and Thain, 2002). Again, by assuming a 5 percent contribution from CH4, the estimated

emission factor will be 790 gCO2e/kWh.

If the geothermal project in question is located near existing geothermal power plants or if there

is emission information available for power plants in geologically analogous conditions, it may

be possible to assume that the emission factors of the existing plants apply to the project being

developed. This is justified if the geothermal resource appears to be of similar geological nature as

those of the neighboring projects.

33G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

Finally, if the available geological information suggest that the geothermal resource in question will be

suitable for zero-emission pumped binary technology, an emission factor of 0 g/kWh can be assumed.

5.1.2. Greenfield Projects Where Exploration Wells Have Been Drilled and Tested

In projects where exploration wells have been drilled and tested, substantial information should be

available for assessing the likely GHG emission factors of a future geothermal power plant. This

includes information on the gas concentration in steam or total fluid from the wells and the reservoir

temperature. At this stage, it is possible to envisage the most appropriate energy conversion

technology for the resource and constrain the steam consumption factor (for back pressure or

condensing plants) or fluid consumption factor (for binary plants). Methods for computing predicted

GHG emission factors for future power plants from well test data are given in Box 5.2. If zero-emission

B O X 5 . 2

Predicting Emissions of Non-Condensable Gases from Geothermal

Power Projects from Well Testing Results

Future GHG emission factors for geothermal power projects can be predicted with reasonable confidence when

exploration wells have been drilled and tested. A different approach is taken for emissions from two-phase binary

plants, on the one hand, and condensing or back pressure plants, on the other. In both cases, it is assumed that the

gas content in the fluid from the exploration wells, weighted by well productivity, is representative for production

wells to be drilled in the project.

Two-Phase Binary Plants

Predicted GHG emission factors (EFGHG

in g/kWh) for two-phase binary plants are computed as:

EF

kJ

kWh

hC C GWPGHG

th

COtf

CHtf

CH

3600

2 4 4( )=

⎡⎣⎢

⎤⎦⎥

η+

pp p

Where:

Δh = Difference between the inlet fluid enthalpy (hi) and the outlet fluid enthalpy (ho) of the plant (in kJ/kg).

The fluid enthalpies are obtained from steam tables for the corresponding temperatures. hi is weighted

by the productivity of the of the production wells (if more than one). ho cannot be lower than the

enthalpy of liquid water at annual average ambient temperature at the project site.

ηth = Thermal net efficiency of the plant (dimensionless). Can range from less than 0.1 to 0.13, depending on

design and resource temperature (DiPippo, 2012). If not known, use 0.1.

Ctf

CO2 = Concentration of CO

2 in the total fluid (g/kg; corresponds to wt%*10).

Ctf

CH4 = Concentration of CH

4 in the total fluid (g/kg; corresponds to wt%*10).

GWPCH 4

= Global warming potential of CH4 valid for the relevant commitment period (t CO

2e/t CH

4). If not known,

use 25.

34C h a p t e r 5

Condensing Plants and Back Pressure Plants

Predicted GHG emission factors for condensing plants and back pressure plants are computed as:

� � � �EF SCF C C GWPMWs

kWh

g

mgGHG CO

s PCHs P

CH

i i

3.61

1000

, ,

2 4 4( )= + ⎡

⎣⎢⎤⎦⎥

⎡⎣⎢

⎤⎦⎥

Where:

SCF = Steam Consumption Factor (SCF) of the power plant (kg/s/MW). SCF is sensitive to inlet pressure

(Pi). The SCF for condensing power plants ranges from 2.4 kg/s/MW at 3 bar-a P i to 1.8 kg/s/MW at

11 bar-a P i (Hudson, 1995). For back pressure plants, the SCF ranges from 5.8 kg/s/MW at 4 bar-a

P i to 4.2 kg/s/MW at 10 bar-a (Hudson, 2003). Note that back pressure plants will have higher GHG

emission factors for the same steam composition than condensing plants due the higher SCF for back

pressure plants.

Cs,P i

CO2 = Concentration of CO

2 in steam at planned inlet pressure, P i (mg/kg). Note that for two-phase wells, the

steam composition is sensitive to sampling pressure, P s. If P s is different from P i, the measured CO2

concentration at P i (Cs,P i

CO2) is computed as:

�C CX

XCOs P

COs P

P

P

i s

s

i,, ,

2 2=

where X P s and X P i

represent the steam fraction at P s and P i, respectively. X P s and X P i

are computed as:

Xh h

h hX

h h

h hP

td l P

v P l P

P

td l P

v P l P

s

s

s s

i

i

i iand ,

,

, ,

,

, ,=

−−

=−−

where htd is the enthalpy of the total discharge (kJ/kg) and hv and hl are the enthalpy of vapor and liquid

(kJ/kg), respectively at the superscripted pressure.

Cs,P i

CO4 = Concentration of CH

4 in steam at inlet pressure, Pi (mg/kg).

GWPCH4

= Global warming potential of CH4 valid for the relevant commitment period (t CO

2e/ t CH

4). If not known,

use 25.

B O X 5 . 2 ( C O N T I N U E D )

pumped binary technology is the selected energy conversion technology at this stage, the future

emissions can be taken to be zero.

5.2. ESTIMATING EMISSION FACTORS FOR BROWNFIELD PROJECTS

The term “brownfield geothermal project” refers to projects that are in capacity drilling or capacity

expansion phases in fields where power plants are already operating. In the case of new projects at

the capacity drilling phase, the GHG emission factors can be predicted based on well testing data

as explained in Box 4.2. GHG emission factors for expansion projects shall be taken to be equal to

35G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

the emission factors for the existing power plant(s), unless there is a well understood reason for not

doing so. This applies if a project expansion is based on wells targeting a part of the reservoir with

different gas content than the production wells of the existing plants. One example of this could be an

expansion project intended to produce from a gas-rich steam cap while existing wells produce from a

liquid-dominated deep reservoir. In such a case, the estimated emission factor should be based on the

well testing data collected from existing production wells drilled in the exploration and capacity drilling

phases of the project (see Box 4.2).

5.3. CONSTRAINING EMISSION FACTORS FOR EXISTING PROJECTS

The Clean Development Mechanism (CDM) methodology for reporting GHG emissions from

geothermal projects, including fugitive emissions of CO2 and CH

4, is outlined in Box 5.3. This

methodology is developed for steam power plants (i.e., condensing and back pressure plants).

However, it can be easily applied to assess emissions from two-phase binary plants by replacing

the word “steam” with “fluid.” The CDM methodology should be followed when determining GHG

emissions of geothermal plants.

The CDM methodology has no provision for addressing gas capture. However, when NCGs are

captured and used either for industrial or agricultural applications or reinjected back into the reservoir,

the amount of gas captured on an annual basis should be subtracted from the annual fugitive

emissions outlined in Box 5.2.

Emission factors from geothermal power plants may change over time but it is difficult to predict with

any certainty whether they will increase, decrease, or remain constant. The conservative approach is

to assume that emission factors remain constant when projecting future emissions. These predictions

should then be revised when actual measurements of gas emissions are collected following the CDM

methodology (see Box 5.3).

5.4. ESTIMATING PLANT CYCLE EMISSION FACTORS FOR GEOTHERMAL POWER PROJECTS

As noted earlier, plant cycle emissions are considered scope 3 emissions under the World Bank GHG

accounting scheme (World Bank, 2015) and the inclusion of such emissions in the GHG accounting

for energy investment operations is optional. Comparison of the available estimates of plant cycle

emissions for geothermal power projects (see section 5.1) to operational emissions (sections 5.2

and 5.3) illustrate that the plant cycle emissions are generally small compared to operational emissions.

Excluding plant cycle emissions from GHG accounting for geothermal power projects, thus, will not

result in significant underestimation of the projects’ total emissions.

If plant cycle emissions (upstream and downstream emissions) are to be included in GHG accounting

for a given geothermal power project, a value of 10 g/kWh should be used for a project lifetime of

30 years. This value—a conservative estimate—is close to the higher end of the estimates available in

the literature.

36C h a p t e r 5

B O X 5 . 3

CDM Methodology for Calculation of Project Emissions from Geothermal1

The calculation of emissions from geothermal projects must take into account two sources of GHGs:

1 | Emissions from fossil fuel combustion. CO2 emissions from the use of fossil fuels for electricity

generation. To be calculated as per the latest version of the “Tool to calculate project or leakage

CO2 emissions from fossil fuel combustion” (available at: https://cdm.unfccc.int/methodologies/

PAmethodologies/tools/am-tool-03-v2.pdf).

2 | Emissions of NCGs from the operation of the geothermal power plant. Fugitive emissions

of CO2 and CH

4 due to the release of NCGs from produced steam. As a conservative approach, the

methodology assumes that all NCGs entering the power plant are discharged to the atmosphere via the

cooling tower. Fugitive CO2 and CH

4 emissions due to well testing and well bleeding are not considered,

as they are considered negligible.

The formula to calculate these fugitive emissions is:

PE w w GWP MGP y steam CO y steam CH y CH steam y, , 2, , 4, ,4( )= + × ×

Where:

PEGP,y

= Project emissions from the operation of geothermal power plants due to the release of NCGs in year y

(t CO2e/yr)

wsteam,CO2,y

= Average mass fraction of CO2 in the produced steam in year y (t CO

2/t steam)

wsteam,CH4,y

= Average mass fraction of CH4 in the produced steam in year y (t CH

4/t steam)

GWPCH4

= Global warming potential of CH4 valid for the relevant commitment period (t CO

2e/t CH

4). If not known,

use 25.

Msteam,y

= Quantity of steam produced in year y (t steam/yr)

The average mass fraction of CO2 and CH

4 must be determined by sampling NCGs in production wells and/or at the

steam field-power plant interface, using ASTM Standard Practice E1675 for sampling two-phase geothermal fluid

for purposes of chemical analysis, at least once every three months.

37

6

G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

A D D R E S S I N G K N O W L E D G E G A P S

T H R O U G H I N V E S T M E N T P R O J E C T S

There are significant uncertainties regarding many aspects of GHG emissions from geothermal power

plants as discussed in Part I. Some of these data gaps could be closed, at least to some degree, by

systematic data collection in new and existing geothermal projects. Three specific areas where the

World Bank and other financial institutions could effectively improve the state of the knowledge of the

geothermal community on GHG emissions from geothermal projects are:

1 | The nature and magnitude of long-term changes in GHG emissions from geothermal power

plants over time

2 | The effect of geothermal power production on CO2 emissions through the surface in

geothermal fields

3 | Cost of capture and treatment of GHG from geothermal power plants for industrial or

agricultural uses

6.1. LONG-TERM CHANGES IN GHG EMISSIONS FROM POWER PLANTS

As discussed above, there is anecdotal evidence of a gradual decrease in CO2 emissions from

geothermal power plants over time. This effect has been attributed to the return of gas-free reinjection

fluid to the reservoir, which dilutes the concentration of dissolved gases in the reservoir fluid and gradual

degassing of the reservoir liquid due to progressive boiling. Publicly available data illustrating this process

are scarce and of varying quality. Furthermore, it is impossible to ascertain whether the available data

are representative for geothermal systems in general or if they are selected for publication because they

show this specific effect. The magnitude of this effect in existing geothermal power plants, thus, is poorly

known and the existing body of data does not allow prediction of future trends for new developments.

Systematic collection of gas emission data from geothermal projects financed by the World Bank,

other multilateral development banks, and project financiers would help to rapidly build up a data set

that could provide a more precise picture of the evolution of GHG emissions from geothermal plants

over time. Such a data set may not allow accurate prediction of future trends in undeveloped systems,

but an expected range of potential GHG emissions variations could be established. Financiers and

developers should agree to obtain data on GHG emissions from plants being developed. Such

agreements could include a confidentiality clause whereby the keeper of the database would commit

to releasing the data only in aggregate, or otherwise untraceable to specific projects, after a given

period of time. This data would need to be centralized at the country level and made publicly available

by the relevant government entity.

Systematic collection of GHG emission data from geothermal projects would not impose additional

costs on the project operators. Gas content in the steam and total fluid are already carefully

38C h a p t e r 6

monitored in modern geothermal power plants as the gas content is an important parameter for the

operation of the plants. It would just be a matter of collecting the information in a central repository for

further analysis.

6.2. EFFECTS OF PRODUCTION ON GHG EMISSIONS THROUGH SOIL AND FUMAROLES

As explained before, geothermal power production may impact surface activity. This may lead to

increasing emissions of geothermal gases through the surface in addition to what is emitted by the

power plant, as in Reykjanes, Iceland, and has likely happened at Wairakei and Ohaaki, New Zealand,

as well. On the other hand, observations from Larderello and Mount Amiata, Italy, indicate that power

production from these systems has resulted in decreasing surface activity.

The data currently available to assess the effect of power production on natural emissions through

the surface, at present, do not allow general predictions to be made, neither on the magnitude of the

effect of production nor on whether the gas emissions will tend to increase or decrease. In order to

accelerate the understanding of these effects, it is necessary to carry out soil gas surveys in different

geothermal fields in a variety of geological settings. The World Bank could contribute to this by funding

baseline CO2 soil emission studies in World Bank-financed geothermal projects, when possible.

Subsequent monitoring studies after power plant commissioning will garner understanding of this

phenomenon within the scientific community and may eventually lead to consideration of these effects

when project emissions are evaluated.

6.3. COST OF GHG CAPTURE AND TREATMENT

There are examples of economically viable capture of geothermal CO2 for industrial and agricultural

purposes (e.g., from the Menderes graben in Turkey) and reinjection of captured geothermal gas is a

topic of research and development. However, capture and treatment of geothermal CO2 is currently

uncommon worldwide. This may be due, in part, to limited awareness of geothermal developers

of the potential economic benefits of capturing geothermal gas for commercial purposes; the

limited understanding of the capital and operational costs involved may also be a limiting factor.

The cost estimates presented in Box 4.2 are general prefeasibility numbers that apply to market

conditions in the United States and may give some guidance for preliminary feasibility evaluation.

However, complete feasibility studies based on site-specific conditions, such as gas supply and

gas composition, and local market circumstances, are necessary for a firm analysis of the economic

viability of such investments.

The World Bank and other multilateral development banks could play an active role in catalyzing

the use of GHG capture technologies in geothermal power projects. The fact is that costs of the

GHG capture and treatment options are often unassessed due to their small potential benefits.

Understanding those costs and their benefits better could be done by encouraging users of World

Bank support to prepare a feasibility analysis of GHG capture for geothermal projects with significant

GHG emissions, limited to projects with expected emission factors above the national grid emission

39A d d r e s s i n g G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

factor or above 250 g/kWh (roughly double the global average emission factor for geothermal plants),

whichever is higher. If GHG capture and treatment is found to be economically feasible for a particular

project, World Bank financing could be provided for the necessary capture investments.

The advantages of this approach are twofold. First, this will encourage investment in GHG capture

where found to be economically feasible and, secondly, this will improve the available information on

the costs of installing and operating these technologies. Increased use of these technologies and

improved information on the cost would raise awareness among other project developers about the

economic benefits of GHG capture from geothermal power plants.

41G r e e n h o u s e G a s e s f r o m G e o t h e r m a l P o w e r P r o d u c t i o n : I n t e r i m T e c h n i c a l N o t e

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EMAIL: ESMAP@WORLDBANK.ORG

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